Technical Field
The present disclosure relates to a method for recovering crude oil from an oil bearing reservoir comprising interbedded carbonate rock layers and, in particular, where a first carbonate rock layer has a relatively high water-soluble sulfate mineral content and a second carbonate rock layer has a relatively low water-soluble sulfate mineral content.
Background of the Technology
It is known that only a portion of oil can be recovered from an oil-bearing reservoir as a result of the natural energy of the reservoir. So-called secondary recovery techniques rely on the supply of external energy to maintain the pressure in a reservoir and to sweep oil towards a production well. The simplest secondary recovery method involves the direct replacement of the oil with another medium, usually water or gas.
“Waterflooding” is one of the most successful and extensively used secondary recovery methods. Water is typically injected, under pressure, into reservoir rocks via injection wells to maintain reservoir pressure and sweep the oil through the rock towards production wells. The water used in waterflooding may be a high salinity water, for example, seawater, estuarine water, a saline aquifer water, or a produced water (water separated from oil and gas at a production facility).
Enhanced oil recovery (EOR) techniques may also be used. The purpose of such EOR techniques is not only to restore or maintain reservoir pressure (as is achieved by a typical waterflood), but also to improve the displacement of the oil from the reservoir, thereby maximizing the recovery of oil from, and minimizing the residual oil saturation of, the reservoir (i.e. the volume of oil present in the reservoir).
One known EOR technique that may be used in carbonate reservoirs is the use of an aqueous displacement fluid that is enriched in sulfate anions. This aqueous displacement fluid may be a pre-formed sulfate enriched water that is injected into the carbonate reservoir or may a sulfate enriched water that is formed in situ by injecting a low salinity water into a carbonate reservoir, thereby achieving in situ dissolution of water-soluble sulfate minerals such as calcium sulfate and magnesium sulfate minerals that are naturally occurring in the carbonate reservoir.
WO 2010/092095 describes a method for enhancing oil recovery from limestone or dolomite comprising determining a SO42−/Ca2+ molar ratio in the connate water; and injecting into the formation pore spaces an aqueous displacement fluid with a SO42−/Ca2+ molar ratio above 1 and a higher SO42−/Ca2+ molar ratio than the connate water. It is said that the method may be applied to modify the wettability of the limestone or dolomite formation such that its oil wettability is reduced and its water wettability is increased.
WO 2012/012235 describes a method for increasing oil production in a carbonate reservoir by conducting a step-wise reduction of salinity of the injected salt water that is injected into the carbonate reservoir. It is said that the method provides for increased oil production as compared to conventional waterflooding techniques.
SPE 154076 (“Improved/Enhanced Oil Recovery from Carbonate Reservoirs by Tuning Injection Water Salinity and Ionic Content”) describes that improved/enhanced oil recovery can be achieved by altering the ionic content of field injection water, and that wettability alteration is the main cause for the substantial increase in oil recovery. According to SPE 154076, the presence of anhydrite in carbonate rock matrix will provide in-situ generation of SO42− which may be important for wettability alteration. SPE 154076 further states that an increase in the reservoir temperature promotes rock wettability alteration, but reduces the dissolution of anhydrite and the in situ generation of SO42−.
Shariatpanahi et al, Energy Fuels 2010, 24, 5997-6008 describes a method for evaluating wetting properties and oil recovery potential by spontaneous imbibition of “smart water” into a low-permeable limestone reservoir. According to Shariatpanahi et al, the benefit of anhydrite present in high temperature carbonate rock is two-fold: (1) the carbonate reservoir can act preferentially to water-wetness; and (2) dissolution of anhydrite in the water front can improve the water-wetness and increase oil recovery in a spontaneous imbibition process.
A problem arises in reservoirs comprising interbedded layers of carbonate rocks having differing levels of water-soluble sulfate minerals as certain layers may contain insufficient amounts of water-soluble sulfate minerals to form the sulfate enriched aqueous displacement fluid such that insignificant incremental oil recovery is achieved from these layers. Thus, achieving optimal incremental oil recovery from a low salinity waterflood in such reservoirs presents technical challenges.